1. Field of Invention
The current invention relates generally to apparatus, systems and methods for extracting oil. More particularly, the apparatus, systems and methods relate to extracting oil from underground deposits. Specifically, the apparatus, systems and methods provide for syngas assisted oil recovery, including at least partially cracking and hydrogenating the oil with syngas.
2. Description of Related Art
A variety of processes are used to recover viscous hydrocarbons such as heavy oil and bitumen from underground deposits. Typically, methods are used in heavy oil or bitumen that are greater than 50 meters deep where it is no longer economic to recover the hydrocarbon by current surface mining technologies. Depending on the operating conditions of the insitu process and the geology of the heavy oil or bitumen reservoir, insitu processes can recover between 25% and 75% of the oil. The primary focus associated with producing hydrocarbons from such deposits is to reduce the insitu viscosity of the heavy oil or bitumen so that it can flow from the reservoir to the production well. The reduction of the insitu heavy oil or bitumen is achieved by raising the temperature and/or dilution with solvent, which is the typical practice in existing processes.
The Steam Assisted Gravity Drainage (SAGD) is a popular insitu recovery method which uses two horizontal wells (a well pair) positioned in the reservoir to recover hydrocarbons. This method is far more environmentally benign than oil sands mining. In this process, the two wells are drilled parallel to each other by using directional drilling. The bottom well is the production well and is typically located just above the base of the reservoir. The top well is the injection well and is typically located between 15 and 30 feet above the production well. Anywhere between 4 and 20 well pairs are drilled on a particular section of land or pad. All the well pairs are drilled parallel to one another, about 300 feet apart, with half of the well pairs oriented in one direction, and the other half of the well pairs typically oriented 180° in the opposite direction to maximize reservoir coverage. A 15 foot meter separation is often an optimal gap which allows for the maximum reservoir production due to the most effective impact of the injected steam. Although the separation between injector and producer wells are planned for 15 foot, some wells have as high as 30 foot gaps, reducing production capability from that particular zone.
The top well injects steam into the reservoir from the surface. In the reservoir, the injected steam flows from the injection well and looses its latent heat to the cool heavy oil and bitumen and as a result the viscosity of the heated heavy oil and bitumen drops and flows under gravity towards the production well located below the injection well.
Given the quantity of steam required for the SAGD, energy needed for the steam generation represents a substantial cost for the SAGD. In addition to the cost, other criteria of the steam generation for the SAGD relate to production of carbon dioxide (CO2) and water input requirements. For example, many governments regulate CO2 emissions. High costs relative to another option for the steam generation can prevent use of some options for the steam generation regardless of ability to provide desired criteria, such as with respect to the production of CO2. Burning gas or oil to fuel burners that heat steam generating boilers creates CO2, which is a greenhouse gas that can be captured by various approaches. While further adding to the cost, capturing the CO2 from flue gases of the burners facilitates in limiting or preventing emission of the CO2 into the atmosphere. In contrast to indirect heating with the boilers, prior direct combustion processes inject steam and CO2 together into the formation even though injection of the CO2 into the formation may not be desired or acceptable in all applications.
Regarding the water input requirements, inability to recycle all of the steam injected results from having to remove impurities such as sodium chloride from any recovered water prior to the recovered water being combined with other make-up water to feed any steam generation. Limited water supplies for the make-up water at locations of where SAGD is applicable can prevent feasibility of the steam generation. Even if available, expense of purchasing water can incur cost for the SAGD.
Typically, the SAGD process is considered thermally efficient if its Steam to Oil Ratio (SOR) is 3 or lower. The SAGD process requires about 1,200 cubic feet of natural gas to heat the water to produce 1 barrel of bitumen. As of the end of 2010, the National Energy Board (NEB) of Canada estimates the capital cost of $18-$22 to produce a barrel of bitumen by the SAGD method. Because of the high ratio of water requirement for the SAGD, an alternative process, method or system to reduce water consumption is desirable.
An alternative process that reduces steam usage is an extension of the SAGD process, the Steam and Gas Push (SAGP) where steam and a non-condensable gas are co-injected into the reservoir. The non-condensable gas provides an insulating layer and improves the thermal efficiency of the process, resulting in a reduction of steam.
Another extension of the SAGD process uses a solvent, called Vapor Extraction (VAPEX). Similar to SAGD, VAPEX consists of two horizontal wells positioned in the reservoir, whereas the top well is the injection well and the bottom well is the production well. In VAPEX, a gaseous solvent such as propane is injected into the reservoir instead of steam. The injected solvent condenses and mixes with the heavy oil or bitumen to reduce its viscosity. Under the action of gravity, the mixture of solvent and bitumen flow towards the production well and are pumped to the surface. A major concern with the VAPEX process is how to control the significant solvent losses to the reservoir, which has a tremendous impact on its economics. Therefore, a better way of extracting heavy oil and bitumen from underground deposits is desired.